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05000259/FIN-2015004-032015Q4Browns FerryCorrective Actions For 2012 Flooding WalkdownsThe inspectors identified an URI associated with potentially deficient flood barrier penetrations in the RHRSW rooms. The inspectors determined that several of the conditions had been previously identified by the licensee and entered into the CAP in November of 2012; however, the conditions had not yet been corrected.Description: Initially, the inspectors identified a potential flood barrier bypass in the B RHRSW room associated with a 2 inch diameter pipe that had significantly corroded an open area through the pipes wall. The inspectors reviewed the licensees response and discovered that an immediate operability determination was hampered because the pipe and valves were not marked or labeled and could not be located on any reviewed drawings. The issue was closed before resolving whether operability of the compartments pumps were affected. Upon additional questioning by the inspectors, the licensee reinitiated investigation of the issue. Since the pipes penetration points could not be readily determined, the licensee closed a manual isolation valve that was discovered upstream of the break in the pipe. Closure of the valve eliminated the potential immediate operability concern. The inspectors also identified that three other previously identified conditions had not been corrected in the B RHRSW room: 1) The B emergency equipment cooling water (EECW) strainer backwash valve conduit was severed where it penetrated the floor of the room, 2) There was an unsealed gap between a conduit sleeve and the enclosed conduit for powering the B1 RHRSW pump, 3) There was a 1/4 inch by 3/8 inch hole in a rubber boot at the B EECW discharge pipe floor penetration. Initial evaluations by the licensee determined that the first condition did not bypass the flood barriers and that the other two would potentially introduce flood water into the compartment at rate of 35 gallons per minute. This amount of inleakage was within the available pumping capacity of a single compartment sump pump and was not an immediate operability concern. However, the licensee has not yet evaluated the aggregate effect of all of the conditions concurrently. Because it is not yet clear whether the identified conditions could allow flood waters to bypass the RHRSW compartment flood barriers, more information is necessary to properly evaluate the licensees past operability evaluations, and the adequacy of the licensees corrective actions. Based on the available documentation of the walkdowns and corrective action documents, it was not clear to the inspectors how the licensee justified the reclassification of the conditions from initially unacceptable status to an indeterminate status and then finally to essentially acceptable status. Future inspection is required to determine if a more than minor performance deficiency or violation exists associated with these issues. Initial reviews have not identified any immediate safety concerns associated with the identified conditions. This issue has been entered in the licensees corrective action program as CRs 1070658, 1075911 and 1119892. (URI 05000259/260/296/2015-004-03, Corrective Actions For 2012 Flooding Walkdowns). These activities constituted four focused annual inspection samples, as defined in Inspection Procedure 71152. Documents reviewed are listed in the attachment.
05000260/FIN-2015004-062015Q4Browns FerryFailure to Identify Significant Steam Leak on the Unit 2 HPCI Turbine STeam Admission ValveA self-revealing Apparent Violation (AV) of 10 CFR Part 50, Appendix B, Criterion XVI, Corrective Actions, was identified for the licensees failure to take corrective following the discovery of a significant steam leak from the packing gland of the Unit 2 HPCI steam inlet isolation valve, 2-FCV-73-16. Specifically, the licensee failed to correctly classify the severity of the leak on 2-FCV-73-16 as described in NPG-SPP-06.8, Leak Reduction Program, and allowed the condition to degrade until packing failure. Upon discovery of the packing failure, the licensee took action to isolate the associated steam leak and declare the HPCI system inoperable. Repairs were completed and tested on September 19, 2015. The licensee entered the issue into their corrective action program as CR 1082405 The performance deficiency was determined to be more-than-minor because it was associated with the Equipment Performance attribute of the Mitigating Systems cornerstone and it adversely affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences (i.e. core damage). Specifically, misclassification of the leak severity as minor led to the loss of function of the HPCI system when valve 2-FCV-73-16 packing degraded until packing failure. The finding could not be screened to Green and is pending a significance determination. The inspectors determined that the finding had a cross cutting aspect of Resolution because the licensee did not take timely corrective action to repair the Unit 2 HPCI steam leak before it lead to a Safety System Functional Failure. (P.3)
05000260/FIN-2015004-052015Q4Browns FerryFailure to Properly Install the Unit 2 HPCI Turbine Steam Admission Valve PackingA self-revealing apparent violation (AV) of 10 CFR Part 50, Appendix B, Criterion III, Design Control was identified for the licensees failure to properly install the Unit 2 High Pressure Coolant Injection (HPCI) turbine steam admission valve packing assembly. The licensee installed a valve packing type that was not as specified in design control drawings and due to inadequate maintenance drawings installed the packing gland follower upside down. Upon discovery of the packing failure, the licensee took action to isolate the associated steam leak and declare the HPCI system inoperable. Repairs were completed and tested on September 19, 2015. The licensee entered the issue into their corrective action program as CRs 1114188 and 1127172. The performance deficiency was more-than-minor because it was associated with the Equipment Performance attribute of the Mitigating Systems cornerstone and it adversely affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences (i.e. core damage). Specifically, the failure to maintain design control led to the loss of function of the HPCI system when valve 2-FCV-73-16 packing failed. The finding could not be screened to Green and is pending a significance determination. The inspectors determined that the finding had a cross cutting aspect of Design Margins because the licensee allowed non-equivalent packing material to be installed in the Unit 2 HPCI steam admission valve. (H.6).
05000260/FIN-2015004-042015Q4Browns FerryFailure to Properly Manage Risk During Planned Maintenance ActivitiesA self-revealing NCV of Technical Specifications (TS) 5.4.1.a was identified for the licensees failure to use appropriate maintenance procedures to ensure appropriate system start functions worked after maintenance activities on the 2A Residual Heat Removal (RHR) Pump breaker. Specifically, the licensees failure to follow procedure MAI-3.3, Cable Terminating and Splicing for Cables Rated up to 15000 Volts resulted in the loose lead in the 2A RHR pump breaker. The licensees immediate corrective actions were to properly tighten the terminal screw. The issue has been entered into the licensees CAP as CR 1040950. The performance deficiency was more than minor because it was associated with the Human Performance attribute of the mitigating systems cornerstone and adversely affected the cornerstone objective to ensure the availability, reliability, and capability of the Unit 2 RHR system to respond to events and prevent undesirable consequences. Specifically, the failure to retighten a terminal screw in the 2A RHR pump breaker resulted in the 2A RHR pump being unable to be started from the control room. The inspectors characterized the finding using IMC 0609, Appendix A, Significance Determination Process, Exhibit 2, Mitigating Systems. The inspectors determined the finding screened as very low safety significance (Green) because the finding did not represent an actual loss of function of at least a single Train for greater than its Tech Spec Allowed Outage Time. The finding does not represent an immediate safety concern because the automatic functions of the RHR pump were not lost and manual starts were available from the 4kV shutdown board. The cause of the finding was directly related to the cross-cutting aspect of Procedure Adherence due to the individuals failing to follow their work instructions. (H.8)
05000259/FIN-2015004-022015Q4Browns FerryFailure to Properly Manage Risk During Planned Maintenance ActivitiesA self-revealing non-cited violation (NCV) of 10 CFR Part 50.65(a)(4) was identified for the licensees failure to properly assess and manage the risk associated with performing maintenance on the Standby Gas Treatment (SBGT) system piping. Specifically, the licensee failed to evaluate the effects of excavation activities associated with the SBGT piping repairs on the condensing coils of the Control Bay (CB) chillers which resulted in the fouling of the condensing coils of the A CB chiller. The licensees immediate corrective action was to clean the A CB chiller condensing coils and restore it to an operable status. The issue was entered into the licensees corrective action program (CAP) as condition report (CR) 1056829. The performance deficiency was more than minor because it was associated with the Equipment Performance attribute of the mitigating systems cornerstone and adversely affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to events and prevent undesirable consequences. Specifically, with the B CB chiller out of service for maintenance, the A CB chiller lost the ability to perform its safety function due to excessive dirt buildup caused, in part, by the nearby excavation activities. The inspectors characterized the finding using IMC 0609, Appendix A, Significance Determination Process, Exhibit 2, Mitigating Systems. The finding was screened to Green because although the A CB chiller was inoperable, the performance deficiency did not cause the loss of system function, and the inoperability did not exceed the 24 hours. The finding does not represent an immediate safety concern because the licensee had cleaned the A CB chiller condensing coils and restored the systems safety function. A cross cutting aspect of Teamwork was assigned due to the licensees Engineering, Maintenance, Work Control, and Operations staffs failure to adequately coordinate or communicate prior to commencing the B CB chiller maintenance. (H.4)
05000259/FIN-2015004-012015Q4Browns FerryHigh Pressure Fire Protection System Piping Failure Following Pump StartThe inspectors identified an Unresolved Item (URI) associated with a high pressure fire protection system pipe rupture on November 7, 2015. On November 7, 2015, following a smoke alarm caused by overheating some food in an operator kitchen (no fire occurred), the B electric fire pump started. Once the B electric fire pump started, a large break developed in a 14 inch section of the high pressure fire system piping between the Unit 1 and 2 diesel generator building and the offgas treatment building. Due to a lack of system pressure caused by the leak, the A and C electric fire pumps and the channel diesel driven fire pump started in their expected sequence. The required system pressure could not be maintained with all four fire pumps running. The leak was not able to be isolated effectively for approximately 1 hour and 13 minutes due to its location. The last successful test of a fire pump at rated system pressure occurred on November 1, 2015. This issue has been entered into the licensees CAP as CR 1102016. The inspectors determined that the licensees analysis of the piping failure mechanism was required to determine if a performance deficiency was associated with the piping rupture. This issue will be tracked as URI 05000259/260/296/2015-004-01, High Pressure Fire Protection System Piping Failure.
05000220/FIN-2013010-022013Q3Nine Mile PointConfiguration Control error results in loss of a vital DC BusThe inspectors documented a self-revealing Green finding of CENGs Conduct of Maintenance procedure, CNG-MN-1.01-1000, because CENG personnel failed to verify they were on the proper equipment prior to commencing maintenance activities. Additionally, Risk Management Activities recommended by CNG-OP-4.01- 1000, Integrated Risk Management, such as temporary barriers and signs were not hung to for the protected #12 SDC train and vital 125 VDC battery bus to ensure workers did not assess protected equipment. The inspectors determined that CENGs failure to follow procedures which resulted in a loss of the vital DC battery bus 12 was a performance deficiency that was within CENGs ability to foresee and prevent. Specifically, a CENG contractor did not follow station procedures for control of maintenance by failing to verify he was on the proper equipment prior to commencing maintenance activities, and station personnel did not implement all risk management actions for protected equipment as directed by station risk management procedures. The performance deficiency was determined to be more than minor because the inspectors determined it affected the configuration control aspect of the Initiating Events cornerstone and adversely affected the associated cornerstone objective to limit the likelihood of events that upset plant stability and challenge critical safety functions during shutdown as well as power operations. The inspectors determined this finding had a cross-cutting aspect in the area of Human Performance, Work Practices, because CENG did not ensure that work practices support human performance. Human error prevention techniques, such as holding prejob briefings, self- and peer-checking, and proper documentation of activities were not completed. Additionally, by not implementing the recommended risk management activities, a tool to ensure a more effective self-check by the worker was removed. Because this performance deficiency does not involve a violation and is of very low safety significance, it is identified as a Finding.
05000220/FIN-2013010-012013Q3Nine Mile PointImproper Bus Restoration Results in a Loss of Shutdown CoolingThe inspectors documented a violation of Unit 1 Technical Specification (TS) 6.4.1, Procedures, because Constellation Energy Nuclear Group (CENG) failed to properly restore from a loss of a vital direct current (DC) bus in accordance with station off-normal procedures resulting in an unplanned loss of all shutdown cooling (SDC) when time to boil was less than 2 hours. Specifically, operators failed to recognize a potential for loss of SDC during battery bus 12 restoration in accordance with N1-SOP- 47A.1, Loss of DC, Revision 00101, and N1-OP-47A, VDC Power System, Revision 02500. The inspectors determined that the failure of CENG to establish an adequate procedure for properly restoring the battery bus 12 was a performance deficiency that was reasonably within CENGs ability to foresee and correct and should have been prevented. The performance deficiency was determined to be more than minor because the inspectors determined it affected the configuration control aspect of the Initiating Events cornerstone and adversely affected the associated cornerstone objective to limit the likelihood of events that upset plant stability and challenge critical safety functions during shutdown as well as power operations. Specifically, CENG failed to specify the associated tripping circuits and tripping actions that could result from battery bus restoration in accordance with N1-SOP-47A.1, Loss of DC, Revision 00101, and N1- OP-47A, VDC Power System, Revision 02500. This performance deficiency resulted in loss of SDC during attempted restoration of the vital DC battery bus 12 on April 16, 2013. A phase III risk assessment was completed by NRC Senior Risk Analysts and .a preliminary greater than green finding and apparent violation letter, dated September 23, 2013, was issued (ML13266A237 AV 05000220/2013003-04). A Regulatory Conference was held in the NRC Region I office in King of Prussia, Pennsylvania, on November 1, 2013, during which CENG was given an opportunity to provide additional information to be considered prior to issuing the final significance determination. On November 5, 2013, and again on November 19, 2013, Significance and Enforcement Review Boards (SERPs) were conducted to discuss the information provided during the regulatory conference. The SERPs concluded that, based upon the information provided during the Regulatory Conference and as discussed in the cover letter of this report, this finding was of very low safety significance. The inspectors determined this finding had a cross-cutting aspect in the area of Human Performance, Resources, because CENG did not ensure that personnel, equipment, procedures, and other resources were available and adequate to assure nuclear safety - complete, accurate and up-to-date design documentation, procedures, and work packages, and correct labeling of components. Specifically, CENG procedures N1-SOP-47A.1 and N1-OP-47A did not contain adequate guidance to ensure recovery from a loss of a DC bus would not result in an unexpected plant transient Unit 1 TS 6.4.1, Procedures, requires, in part, that written procedures and administrative policies shall be established, implemented, and maintained that cover the applicable procedures recommended in Regulatory Guide 1.33, Quality Assurance Program Requirements (Operation), Appendix A, Typical Procedures for Pressurized- Water Reactors and Boiling-Water Reactors, dated November 3, 1972. Regulatory Guide 1.33, Appendix A, Section 4, Procedure for Startup, Operation, and Shutdown of Safety-Related BWR Systems, requires procedures for onsite DC system, and Section 6, Procedures for Combating Emergencies and Other Significant Events, requires, in part, procedures for including loss of electrical power (and/or degraded power sources). CENG procedures N1-OP-47A, 125 VDC Power System, Revision 02500, and N1- SOP-47A.1, Loss of DC, Revision 00101, implement this requirement. Contrary to the above, as of April 16, 2013, NMP did not establish adequate procedures for the onsite DC system to include a loss of electrical power. Specifically, following the loss of a vital DC battery bus 12, operators attempted to restore power using implementing procedures N1-OP-47A and N1-SOP-47A.1. While those procedures indicated tripping circuits and tripping actions may be carried out when power is reestablished, the procedures did not specify all of the affected components, including SDC pumps. As a result, when operators attempted to re-establish power, the site temporarily lost all SDC capability. Because this violation is of very low safety significance (Green) and CENG entered this issue into its corrective action program as CR-2013-002926 and CR-2013-002916, this violation is being treated as a non-cited violation (NCV) consistent with Section 2.3.2 of the NRC Enforcement Policy.
05000387/FIN-2013013-022013Q2SusquehannaFailure to Follow RCA Egress RequirementsThe contractors actions caused PPL to violate the SSES operating license. Specifically, SSES License Condition 2.C(2) requires that PPL will operate SSES in accordance with the TS. SSES TS 5.4.1, in part, requires that written procedures shall be implemented covering the procedures recommended in RG 1.33, Rev 2, App A, February 1978. RG 1.33, Rev 2, App A, recommends the establishment of radiation protection procedures for access control to radiation areas and for contamination control. Pertaining to the second OI Investigation (1-2012-043), PPL implementing procedure NDAP-QA-0626, Radiologically Controlled Area Access and Radiation Work Permit System states that individuals are not allowed to move radiological postings, barricades, and barriers and to contact HP if there is a need to have any of these items moved or modified. Contrary to the above, on March 30, 2012, a contract carpenter did not contact the SSES HP department and, instead, moved an HRA posting on his own. Pertaining to the third OI Investigation (1-2011-030), PPL implementing procedure NDAP-QA- 0623, Radiation Protection Standards and Responsibilities requires individuals to not leave the RCA until they can successfully pass through a PCM and a PM. Contrary to the above, on April 6 and April 7, 2011, contract employees left the SSES RCA without successfully passing through both a PCM and a PM. Because the violations associated with the second and third OI investigations were caused by the willful actions of contract employees, they were evaluated under the NRCs traditional enforcement process using the factors set forth in Section 2.3.2 of the NRC Enforcement Policy. After careful consideration of these factors, the NRC concluded that these violations should be classified at Severity Level IV. In reaching this decision, the NRC considered that the significance of the underlying violations was minor because: (1) pertaining to OI investigation 1-2012-043, the HRA was conservatively posted and physical access into the actual HRA overhead did not occur; and, (2) pertaining to OI investigation 1-2011-030, both individuals successfully cleared other contamination monitors and the issue did not involve the spread of radioactive contamination into an uncontrolled area. However, the NRC decided to increase the significance of the violations since they were willful and the NRC regulatory program is based, in part, on licensees and their contractors acting with integrity.
05000387/FIN-2013013-012013Q2SusquehannaUnauthorized Movement of a High Radiation Area BoundaryThe first OI investigation (1-2012-012), which was completed on August 23, 2012, examined whether a contract roofer at SSES deliberately failed to follow an SSES procedure pertaining to personnel contamination monitoring. Based on the evidence gathered during the OI investigation, the NRC concluded that on October 11, 2011, the contract roofer willfully, with careless disregard, failed to contact the SSES Health Physics (HP) department after receiving two radiation portal monitor (PM) alarms when exiting the SSES protected area (PA). Specifically, on the specified occasion, after the contract roofer received a second alarm on a PM at the SSES PA exit, one of the NRC resident inspector staff, while exiting the SSES PA, observed the contractor and reminded him of the requirement to contact HP. Because the contract roofer could not locate a telephone in the area, his coworker (who had successfully passed the PM and exited the PA) approached a SSES security officer stationed at the security control point, purportedly to request assistance with contacting the HP department. As a result of a likely miscommunication, the HP department was not contacted and the contract roofer used a different PM and exited the PA after not receiving an alarm, even though, in accordance with his testimony to OI, the contract roofer knew he was supposed to contact the HP department and wait for assistance. Although the contract roofers coworker testified to OI that a security officer at the security control point had told him to have the contract roofer try another PM, OI, through its investigation, was unable to corroborate that any security officer provided such direction. The contract roofers actions caused PPL to violate the SSES operating license. The violation is described in the enclosed Notice of Violation (Notice).
05000220/FIN-2013003-042013Q2Nine Mile PointImproper Bus Restoration Results in a Loss of Shutdown CoolingA self-revealing apparent violation of Technical Specification (TS) 6.4.1, Procedures, was identified at Unit 1 because CENG failed to properly recover from a loss of a vital direct current (DC) bus in accordance with station off-normal procedures resulting in an unplanned loss of all shutdown cooling (SDC) when time to boil was less than 2 hours. Specifically, during the restoration from the loss of battery bus 12, operators failed to identify a SDC trip signal before attempting restoration of the DC bus, which ultimately lead to a SDC pump trip (i.e. loss of decay heat removal from the reactor). Corrective actions included conducting a prompt human performance event review, entering the issue into their corrective action program (CAP), and conducting a root cause analysis. Planned corrective actions include a review of all emergency, off-normal, and normal system operating procedures. The inspectors determined that CENGs failure to properly restore battery bus 12 in accordance with N1-SOP-47A.1, Loss of DC, Revision 00101, and N1-OP-47A, 125 VDC Power System, Revision 02500, was a performance deficiency that was reasonably within CENGs ability to foresee and correct and should have been prevented. The performance deficiency was determined to be more than minor because the inspectors determined it affected the configuration control aspect of the Initiating Events cornerstone and adversely affected the associated cornerstone objective to limit the likelihood of events that upset plant stability and challenge critical safety functions during shutdown as well as power operations. The significance of the finding is designated as To Be Determined (TBD) until a Phase 3 analysis can be completed by the NRCs Senior Reactor Analysts. The inspectors determined this finding has a cross-cutting aspect in the area of Human Performance, Resources, because CENG did not ensure that personnel, equipment, procedures, and other resources were available and adequate to assure nuclear safety - complete, accurate and up-to-date design documentation, procedures, work packages, and correct labeling of components. Specifically, CENG procedures N1-SOP-47A.1 and N1-OP-47A did not contain adequate guidance to ensure recovery from a loss of a DC bus would not result in an unexpected plant transient.
05000277/FIN-2012003-032012Q2Peach BottomADS SRV Actuator Diaphragm Thread Seal LeakOn September 25, 2011, while Peach Bottom Unit 3 was shut down for a scheduled refueling outage, Exelon personnel performed a routine ST on the Unit 3 71B SRV. The valve exceeded the maximum allowable leak rate for the pneumatic actuation controls associated with its ADS function, and Exelon declared SRV 71B inoperable. Exelon determined that the cause of the excessive leak rate was a failure of the 71B SRV actuator diaphragm thread seal, as a result of thermal degradation of the SRV actuator diaphragm thread seal material. The seal had been replaced during a November 2010 maintenance outage and, at that time, the SRV had passed its ST. Because no other leak testing had occurred since November 2010 (because the plant had been operating and the SRV is inside primary containment), Exelon could not assure that the SRV had been operable since the completion of the last successful leak test. Accordingly, Exelon concluded that it had not met the requirements of TS 3.5.1, Action E.1, which requires that, with one ADS valve inoperable, the licensee must return the valve to operable status within 14 days or be in Mode 3 within 12 hours. Exelon replaced the degraded 71B SRV thread seal on September 26, 2011, and the valve passed a subsequent leak test. Exelon also entered the 71B SRV failure into the CAP (IR 1268076), and, in accordance with 10 CFR 50.73(a)(2)(i)(B), submitted LER 11-003 to report to the NRC this condition prohibited by TSs. When inspected by Exelon maintenance personnel, Exelon identified that the thread seal had indications of being dry and brittle. Subsequent review by Exelon engineering personnel determined that the apparent cause of the seal leakage was the result of thermal degradation of the thread seal material. The NRC reviewed the licensees evaluation and actions related to this matter and concluded that the degraded seal condition was not caused by improper maintenance practices. Also, trend data did not indicate a potential degradation in that the same seal material had been used at PBAPS Units 2 and 3 for the last 20 years with no other failures. Further, the NRC considered that the 71B seal leakage would not have been detectable during normal plant operations, since it only occurred when the valve was actuated. Consequently, the NRC concluded that the inoperability of the 71B SRV was not within Exelons ability to foresee and correct, and therefore, did not identify any performance deficiency associated with the violation. The inspectors assessed the risk associated with the issue by using IMC 0609, Appendix G, Shutdown Operations SDP. The inspectors screened the issue, and evaluated it using Checklist 6 of IMC 0609, Appendix G, Attachment 1. SRV 71B is one of five PBAPS Unit 3 ADS reactor vessel relief valves. In order to perform the ADS system safety function, four of the five ADS SRVs are required to function. The four other ADS SRVs passed the leakage test, and would have been capable of depressurizing the reactor pressure vessel for design basis events. Therefore, during the period the 71B SRV was inoperable, the overall ADS safety function was maintained. As a result, this issue would screen as very low safety significance Because it was not reasonable for the licensee to be able to foresee and prevent the thread seal material degradation, or to have made the 71B SRV inoperability decision at an earlier time, the inspectors determined that no performance deficiency exists. Because no performance deficiency was identified, no enforcement action is warranted for this violation of NRC requirements in accordance with the NRCs Enforcement Policy. Further, because licensee actions did not contribute to this violation, it will not be considered in the assessment process or the NRCs Action Matrix.
05000277/FIN-2012003-022012Q2Peach BottomLicensee-Identified ViolationTS LCO 3.3.5.1, Condition E, requires that one inoperable channel of CS system bypass valve instrumentation be restored to operable in seven days, and, if the redundant emergency core cooling system initiation capability is inoperable, the supported feature(s) must be declared inoperable within one hour. Additionally, TS LCO 3.5.1, Condition I, requires that with two CS subsystems inoperable, LCO 3.0.3 be entered immediately. Contrary to the above, the A and D CS pump bypass valve instrumentation were both inoperable on April 18, 2012, for a period of time greater than one hour, the supported features were not declared inoperable, and LCO 3.0.3 was not immediately entered. Specifically, following discovery of the A CS pump bypass instrument inoperability during ST on April 18, 2012, the D CS pump bypass instrument was discovered to be inoperable on April 19, 2012. PBAPS determined that it was likely that the D CS instrument was also inoperable April 18, 2012, and therefore this event was reportable (see section 4OA3.3). Following successful recalibration, both switches were returned to an operable status on the day of their respective surveillance testing. The inspectors determined that this event screens to Green using the Table 4a screening criteria in Attachment 4 of IMC 0609, SDP, because there was no loss of the CS system safety function. Because this finding is of very low safety significance, and has been entered into Exelon\'s CAP under IR 1355773, this violation is being treated as a Green NCV consistent with the NRCs Enforcement Policy.
05000353/FIN-2012008-022012Q2LimerickViolation of TS 3.5.1 and 3.0.3The inspectors determined that the failure to revise LER 05000353/2011-003-00 within 60 days of July 21, 2011, to include the violations of TS 3.5.1 and 3.0.3 in accordance with 10 CFR Part 50.73 was a performance deficiency that was reasonably within Exelons ability to foresee and correct, and should have been prevented. Because the issue impacted the regulatory process, in that a violation of Technical Specifications was not reported to the NRC within the required timeframe and the NRCs opportunity to review the matter in its entirety was delayed, the inspectors evaluated this performance deficiency in accordance with the traditional enforcement process. Using example 6.9.d.9 from the NRC Enforcement Policy, the inspectors determined that the performance deficiency was a SL-IV violation, because Exelon personnel failed to make a report required by 10 CFR Part 50.73 when information that the report was required had been reasonably within their ability to have identified. The significance of the associated performance deficiency was screened against the ROP per the guidance of IMC 0612, Appendix B, and the inspectors determined it to be minor because it was not similar to Appendix E examples, was not a precursor to a significant event, did not cause a PI to exceed a threshold, did not adversely affect cornerstone objectives, and if left uncorrected would not have lead to a more significant safety concern. As such, no ROP finding was identified and no crosscutting aspect was assigned.
05000443/FIN-2012503-012012Q2SeabrookFailure of Exercise Critique to ldentify an RSPS Weakness as a DEP Pl Opportunity FailureThe NRC identified an apparent violation (AV) for the licensee exercise critique process not properly identifying a weakness associated with a risk significant planning standard (RSPS) that was determined to be a Drill/Exercise Performance (DEP) Performance Indicator (Pl) opportunity failure during a full-scale exercise. The AV is associated with emergency preparedness planning standards 10 CFR 50.47(bX14) and 10 CFR 50.47(bX5) and the requirements of Section lV.F.2.g of Appendix E to 10 CFR Part 50. This finding was entered into the licensee corrective action program. The failure of NextEra to identify the exercise weakness related to an incorrect protective action recommendation (PAR) notification during their exercise critique was a performance deficiency that was reasonably within NextEra ability to foresee and prevent. The finding is more than minor because it is associated with the emergency response organization attribute of the Emergency Preparedness Cornerstone and affected the cornerstone objective to ensure that the licensee is capable of implementing adequate measures to protect the health and safety of the public in the event of a radiological emergency. This finding was determined to potentially have greater-than- Green safety significance because the licensee exercise critique process did not properly identify a weakness associated with a RSPS that was determined to be a DEP Pl opportunity failure during a biennial full-participation exercise. The finding is related to the cross-cutting area of Problem identification and Resolution, Corrective Action Program; in those NextEra personnel did not identify a RSPS issue completely, accurately, and in a timely manner commensurate with the safety significance. Specifically, during the biennial full-participation exercise evaluation Next Era failed to identify a weakness.
05000277/FIN-2012003-012012Q2Peach BottomInadequate Test Control to Demonstrate RCIC System Design Basis Start-up Response TimeThe inspectors identified a NCV of very low safety significance of Title 10 Code of Federal Regulation (CFR) 50, Appendix B, Criterion XI, Test Control, because Exelon conducted unacceptable pre-conditioning of the reactor core isolation cooling (RCIC) system during response time testing. The performance deficiency was related to Exelons surveillance test (ST) procedure which required cold startup of RCIC to reach the rated pump discharge pressure and flow rate within 50 seconds. Exelon procedures required a 72 hour standby period between pump starts to ensure the pump cold start design criteria are satisfied without pre-conditioning. On numerous occasions, when the pump design parameters were not reached in less than 50 seconds on the first attempt, control room operators would routinely perform a second start attempt within a short period of time, typically less than one hour, to adjust the RCIC pump controls and attain the design values in less than or equal to 50 seconds. Exelon performed an extent of condition review of Units 2 and 3 RCIC cold start test data to ensure the current pump, valve, and flow results satisfied the response time testing requirements. The violation was entered into the corrective action program (CAP) as issue report (IR)1364066. The performance deficiency was more than minor because it was similar to IMC 0612, Appendix E, Examples of Minor Issues, example 2.a. Specifically, the RCIC cold start ST procedure was not implemented adequately to ensure that the RCIC pump design discharge pressure and flow were reached within the 50 second requirement on the first attempt. The inspectors evaluated the finding using IMC 0609, Attachment 4, Initial Screening and Characterization of Findings, and determined the finding was of very low safety significance (Green) because all of the mitigating system barrier questions in Table 4.a resulted in a no response. The finding included a cross-cutting aspect in the area of Work Practices, Human Performance component, because Exelon did not effectively communicate expectations regarding procedural compliance and personnel following procedures. Specifically, Exelon took credit for the Unit 2 ST performed on April 7, 2011, which started and shutdown RCIC three times in less than 72 hours to satisfy the response time testing acceptance criteria. On January 20, 2011, the same test was performed for Unit 3, when the RCIC system was run two times prior to satisfying the acceptance criteria. Exelon did not identify the unacceptable pre-conditioning of the RCIC system start-up time for either test because personnel did not follow the In-service Testing (IST) Program Corporate Technical Position procedure.
05000353/FIN-2012008-012012Q2LimerickFailure to Submit an LER Revision for Conditions Prohibited by TS Associated with the HPCI and RCIC SystemsThe inspectors identified a SL-IV non-cited violation (NCV) of 10 CFR Part 50.73, Licensee Event Report System, because violations of Technical Specifications (TS) 3.5.1 and 3.0.3 for the condition of the high pressure coolant injection (HPCI) and RCIC systems being simultaneously inoperable were not reported to the NRC within 60 days of discovery. After this was identified by the inspectors, the issue was entered into Exelons Corrective Action Program (CAP) as IR 1377559. The inspectors determined that the failure to revise Licensee Event Report (LER) 05000353/2011-003-00 within 60 days of initial issuance on July 21, 2011 to include the violations of TS 3.5.1 and 3.0.3 in accordance with 10 CFR Part 50.73 was a performance deficiency that was reasonably within Exelons ability to foresee and correct, and should have been prevented. Because the issue impacted the regulatory process, in that a violation of Technical Specifications was not reported to the NRC within the required timeframe and the NRCs opportunity to review the matter in its entirety was delayed, the inspectors evaluated this performance deficiency in accordance with the traditional enforcement process. Using example 6.9.d.9 from the NRC Enforcement Policy, the inspectors determined the performance deficiency was a SL-IV violation, because Exelon personnel did not make a report required by 10 CFR Part 50.73. The significance of the associated performance deficiency was screened against the ROP per the guidance of IMC 0612, Appendix B, and the inspectors determined it to be minor because it was not similar to Appendix E examples, was not a precursor to a significant event, did not cause a performance indicator (PI) to exceed a threshold, did not adversely affect cornerstone objectives, and if left uncorrected would not have lead to a more significant safety concern. As such, no ROP finding was identified and no cross-cutting aspect was assigned.
05000387/FIN-2012008-012012Q1SusquehannaInadequate Gain Settings Result in Reactor ScramA self-revealing finding of very low safety significance was identified when Unit 1 automatically scrammed from 32 percent power on April 22, 2010, due to low reactor water level. PPL entered inadequate gain settings in the feedwater digital ICS for reactor feed pump turbine (RFPT) speed control as part of the ICS design modification, and the test procedure, which was in progress at the time, did not specify exit criteria that would have ended the test prior to an automatic scram. PPL completed corrective actions related to the direct cause by updating the RFPT speed control characterizer block gain settings. This issue was entered in PPLs CAP as condition report (CR) 1257781 (April 2010) and CR 1348940 (January 2011). The inspectors determined that inadequate procedures to perform post-modification testing on the digital ICS was a performance deficiency because the testing performed did not detect incorrect gain settings prior to a reactor scram. The inspectors screened the performance deficiency in accordance with IMC 0612, Appendix B, Issue Screening. The performance deficiency was determined to be more than minor because the finding was associated with the Initiating Events cornerstone attribute of Design Control, and affected the cornerstone objective of limiting the likelihood of those events that upset plant stability and challenge critical safety functions during power operation. The inspectors evaluated the finding using IMC 0609, Attachment 4, Initial Screening and Characterization of Findings, and determined the finding did not contribute to both the likelihood of a reactor trip and the likelihood that mitigation equipment would not be available. Consequently, the finding is of very low safety significance (Green). This finding has a cross-cutting aspect in the area of Human Performance, Work Control, because PPL did not plan and coordinate work activities consistent with nuclear safety. Specifically, PPL did not appropriately consider risk during the design modification and did not have adequate planned contingencies for the testing of the new digital ICS.
05000333/FIN-2011009-022011Q4FitzPatrickFailure to implement procedures required by TS 5.4.1The FitzPatrick Technical Specification Section 5.4.1 states, in part, that written procedures shall be established, implemented, and maintained for the applicable procedures recommended in the Regulatory Guide (RG) 1.33, Appendix A (November 1972 edition). Appendix A, Section G of the RG identifies radiation protection procedures for control of radioactivity for limiting materials released to the environment and limiting personnel exposure. These include access control to radiation areas, contamination control, and personnel monitoring. Section H.2.b of the RG identifies radiation protection and surveillance tests that should be covered by written procedures. These include inspections and calibrations for each surveillance test, inspection, or calibration listed in the technical specifications. 10 CFR 20.1501 (a) states, in part, that each licensee shall make or cause to be made, surveys that may be necessary for the licensee to comply with the regulations in this part; and are reasonable under the circumstances to evaluate the magnitude and extent of radiation levels, concentrations or quantities of radiation levels, and the potential radiological hazards. A. Entergy procedure RP-OPS-08.01, Revisions 13-16, Routine Surveys and Inspections, Section 6.2, requires that daily surveys and inspections be documented on Attachment 1. Contrary to the above, on mUltiple occasions from 2006 to 2009, RPTs failed to perform daily surveys of the Reactor Building 326 foot elevation airlock. B. FitzPatrick Procedure RP-RESP-03.01, Drywell Continuous Atmospheric Monitoring System, Revisions 18-27, provides instructions for operation and calibration of the General Atomics Electronic Systems Drywell Continuous Atmosphere Monitoring System(s) (DWCAM). It specifies that after valve manipulations, a second individual must verify correct valve position. Attachment 1 documents weekly data and requires initials and signatures for independent verification of valve manipulations performed during these checks. Contrary to the above, on eleven occasions between September 2007 and December 2009, DWCAM valves were manipulated, and an independent verification of the DWCAM valve position was not performed by a second Radiation Protection Technician (RPT). On these occasions, the second verification signature was obtained some undetermined length of time after the surveillance test from an RPT determined to have been on duty the day of the test (but who did not actually perform the independent verification) by the RPT who initially performed the test. C. Entergy procedure EN-RP-104, Personnel Contamination Events, Revisions 14, provides contamination monitoring requirements, and instructions for response to contamination alarms. Specifically, Section 5.6, Documentation of Events requires a condition report, Personnel Contamination Event Log, or Personnel Contamination Event Record, be completed depending on the contamination level. Contrary to the above, on at least one occasion, on an undetermined date prior to June 2009, an RPT did not document a personnel contamination event that exceeded the documentation threshold. Specifically, while the technician took action to address the radiologically controlled area (RCA) exit portal monitor alarm and decontaminate the individuals, the technician did not document a personnel contamination event as required. D. Entergy procedure EN-RP-100, Radworker Expectations, Revisions 0-3, provides basic Radiation Protection (RP) requirements and expectations for radiation workers engaged in radiological work at Entergy nuclear facilities. Section 1.0, Purpose, states that, Adrlerence to these requirements and expectations contributes significantly to the minimization of personnel exposure to radiation and radioactive material and the minimization of personnel contaminations. Section 5.6, Contamination Control, requires that personal items be scanned prior to exiting an RCA. Contrary to the above, on one occasion on an undetermined date prior to June 2009, an RPT removed contaminated personal items from an RCA without having them scanned through the contamination monitor at an RCA exit.
05000277/FIN-2011005-022011Q4Peach BottomFailure to Establish, Implement, and Maintain Adequate QA for Effluent and Environmental MonitoringThe inspectors identified a Green finding associated with the failure to establish, implement, and maintain adequate quality assurance (QA) program elements in the area of effluent and environmental monitoring as required by Peach Bottom, Units 2 and 3 Technical Specification (TS), Section 5.4.1. Specifically, Exelon\\\'s QA program for effluent and environmental monitoring was not sufficient to ensure: 1) that both adequate and timely evaluation and assessment of changes described in the Public Land Use Census were conducted for purposes of dose validation and sampling program modification; 2) that changes in meteorological parameters, used for public dose projections and assessment, were promptly and adequately evaluated; and 3) that laboratory QA programs for effluent and environmental sample analysis measurement systems were adequate and implemented properly. Exelon placed these issues in its CAP as Action Requests (ARs): 1226969, 1226202,1299543, 1299476,1302720, and 1303308. The finding is more than minor because it is associated with the Public Radiation Safety cornerstone attribute of programs and processes and adversely affected the associated cornerstone objective in that failure to establish, implement, and maintain an adequate QA program in the effluents and environmental monitoring program area adversely affected the licensee\\\'s ability to ensure adequate protection of public health and safety. The finding was assessed for significance using IMC 0609, Appendix D, and determined to be of very tow safety significance (Green) because: the issue was contrary to TSs and is a radioactive effluent release program deficiency; there was no indication of a spill or release of radioactive material on the licensee\\\'s site or to the offsite environs that would impact public dose assessment, and there was no substantial failure to implement the radioactive effluent release program. The licensee re-assessed the dose to members of the public from routine releases and determined that projected doses did not, nor were likely to, exceed applicable limits, including as low as is reasonably achievable (ALARA) design specifications of 10 CFR Part 50, Appendix l; or 10 CFR 20.1301(e). The cause of this finding is related to the cross-cutting area of Human Performance, Work Practices, Aspect H.4(b) because the licensee did not ensure Personnel followed procedure compliance requirements activities for effluent and environmental monitoring program.
05000333/FIN-2011009-032011Q4FitzPatrickFailure to maintain complete and accurate records as required by 10 CFR 50.9 and TS 5.4.1.10 CFR 50.9 states, in part, that information required by statue or by the Commission\\\'s regulations, orders, or license conditions to be maintained by the licensee shall be complete and accurate in all material respects. The FitzPatrick Technical Specification Section 5.4.1 states, in part, that written procedures shall be established, implemented, and maintained for the applicable procedures recommended in the RG 1.33, Appendix A (November 1972 edition). Appendix A, Section G of the RG identifies radiation protection procedures for control of radioactivity for limiting materials released to the environment and limiting personnel exposure. These include access control to radiation areas, contamination control, and personnel monitoring. Section H.2.b of the RG identifies radiation protection and surveillance tests that should be covered by written procedures. These include inspections and calibrations for each surveillance test, inspection, or calibration listed in the technical specifications. A. FitzPatrick procedure RP-RESP-04.09, Portacount Respirator Fit Testing, Revision 10, provides the requirements, procedure, and acceptance criteria for respirator fit testing. Section 3.2.1 states that the records generated by the performance of the procedure are considered quality records. Contrary to the above, on multiple, but an indeterminate number of occasions between 2006 and 2009, respirator fit testing records maintained by the licensee were not complete and accurate in all material respects in that the annual quantitative respirator fit test qualification records for several involved individuals indicated that the tests were performed, when in fact, the fit tests had not been conducted. B. FitzPatrick Procedure RP-RESP-03.01, Drywell Continuous Atmospheric Monitoring System, Revisions 18-27, provides instructions for operation and calibration of the DWCAM. It specifies that after valve manipulations, a second individual must verify correct valve position. Attachment 1 documents weekly data and requires initials and signatures for independent verification of valve manipulations performed during these checks. Contrary to the above, on at least 11 occasions between September 2007 and December 2009, DWCAM surveillance records maintained by the licensee were not complete and accurate in all material respects in that procedurally required signatures for independent verification of valve manipulation were either forged (two instances) or entered after work completion by personnel who did not actually perform the verifications (nine instances). These procedure records were material since they are identified by the licensee as quality records.
05000333/FIN-2011009-012011Q4FitzPatrickPermitting the use of respiratory protection equipment to limit the intake of radioactive material10 CFR 20.1703 states, in part, that if the licensee assigns or permits the use of respiratory protection equipment to limit the intake of radioactive material, the licensee shall implement and maintain a respiratory protection program that includes fit testing before the first field use of tight fitting, face-sealing respirators and periodically thereafter at a frequency not to exceed one year. It further states that the licensee shall ensure that no objects, materials or substances, such as facial hair, or any conditions that interfere with the face-faceplate seal or valve function, and that are under the control of the respirator wearer, are present between the skin of the wearer\'s face and the sealing surface of a tight-fitting respirator face piece. Fitzpatrick implementing procedure RP-RESP-04.09, Portacount Respirator Fit Testing, Revision 10, provides the requirements, procedure, and acceptance criteria for respirator fit testing. Section 6.2, Respirator Quantitative Fit Testing, Step 6.2.6 requires that the individual being tested must don the respirator. Contrary to the above, on multiple, but an indeterminate number of occasions between 2006 and 2009, several individuals who were required to have been respirator fit tested did not have the respirator fit tests performed within the required annual frequency, in that they did not don the respirator to verify proper fit.
05000353/FIN-2011004-012011Q3LimerickFailure of Feedwater MOV Resulting in RCIC Inoperability for Longer than Allowed by Technical SpecificationsA self-revealing preliminary white finding and apparent violation of Technical Specification (TS) 3.7.3, Reactor Core Isolation Cooling System and TS 3.6.3, Primary Containment Isolation Valves, was identified. The inspectors determined that the failure by Exelon to ensure sufficient technical guidance was contained in operating procedures to: 1) ensure that a Main Feedwater system (FW) motor-operated valve (MOV) could close against expected system differential pressures and 2) prevent operators from attempting to close FW MOVs out of sequence resulting in differential pressures for which they are not designed; is a performance deficiency. This resulted in the Reactor Core Isolation Cooling system (RCIC) and a Primary Containment Isolation Valve (PCIV) being inoperable from April 23 to May 23, 2011, due to FW MOVs HV-041-209B and HV-041-210 failing to fully shut. As a result, both safety related systems were inoperable for greater than their Technical Specification allowed outage times. Specifically, operations procedures did not contain adequate technical guidance to ensure that operations personnel operated HV-041209 A&B and HV-041-210 in the proper sequence to remain within valve design limitations. This resulted in the HV-041-209B and HV-041-210 valves failing to fully close on April 22, 2011, although they indicated closed in the Main Control Room. Upon identification, Limerick operations staff fully closed the valves restoring RCIC and PCIV operability, entered the issue into the CAP as issue report (IR) 1219476 and conducted a cause evaluation. Subsequent corrective actions included an extent-of-condition review, revisions to the operating procedure, and revisions to maintenance and testing procedures. The inspectors determined that this finding is more than minor because it is associated with the equipment performance attribute of the Mitigating Systems Cornerstone and affects the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, operating procedures, maintenance and testing were not adequately implemented to ensure that the design capability of HV-041-209B and HV-041-210 to close against expected system differential pressures was maintained. The finding was evaluated using NRC Inspection Manual Chapter 0609 Appendix A, User Guidance for Significance Determination of Reactor Inspection Findings for At-Power Situations. Phase I, II, and III evaluations were conducted. The NRC total estimated L\\\\CDF in this preliminary assessment is Low E-6/yr (WHITE) and the NRC total estimated Large Early Release Frequency (LiLERF) in this preliminary assessment is 3.6E-9/yr (GREEN). The inspectors also determined that this issue has a cross-cutting aspect in the area of Human Performance, Resources, because Exelon did not ensure long term plant safety by maintaining design margins and minimizing preventive maintenance deferrals (H.2. (a)). Specifically, design limitations of the HV-041209 A & B valves were not adequately captured in the procedural guidance, which contributed to the operators continuing on in the procedures for securing the FW long path recirculation line up when problems with the HV-041-21 0 valve were encountered. Additionally preventive maintenance activities which could potentially have prevented this issue were deferred without an appropriate evaluation.
05000293/FIN-2011012-012011Q3PilgrimFailure to Implement Conduct of Operations and Reactivity Control Procedures during Reactor StartupA self-revealing finding was identified involving the failure of Pilgrim personnel to implement conduct of operations and reactivity control standards and procedures during a reactor startup, which contributed to an unrecognized subcriticality followed by an unrecognized return to criticality and subsequent reactor scram. The significance of the finding has preliminarily been determined to be White, or of low to moderate safety significance. The finding is also associated with one apparent violation of NRC requirements specified by Technical Specification 5.4, Procedures. There was no significant impact on the plant following the transient because the event itself did not result in power exceeding license limits or fuel damage. Additionally, interim corrective actions were taken, which included removing the Pilgrim control room personnel involved in the event from operational duties pending remediation, providing additional training for operators not involved with the event, and providing increased management oversight presence in the Pilgrim control room while long term corrective actions were developed. Entergy staff entered this issue, including the evaluation of extent of condition, into its corrective action program (CR-PNP-2011-2475) and performed a Root Cause Evaluation (RCE). The finding is more than minor because it was associated with the Human Performance attribute of the Initiating Events cornerstone and affected the cornerstone objective of limiting the likelihood of those events that upset plant stability and challenge critical safety functions during power operations. Specifically, the failure of Pilgrim personnel to effectively implement conduct of operations and reactivity control standards and procedures during a reactor startup caused an unrecognized subcriticality followed by an unrecognized return to criticality and subsequent reactor scram. Because the finding primarily involved multiple human performance errors, probabilistic risk assessment tools were not well suited for evaluating its significance. The inspection team determined that the criteria for using IMC 0609, Appendix M, Significance Determination Process Using Qualitative Criteria, were met, and the finding was evaluated using this guidance, as described in Attachment 4 to this report. Based on the qualitative review of this finding, the NRC has preliminarily concluded that the finding was of low to moderate safety significance (preliminary White). The inspection team determined that multiple factors contributed to this performance deficiency, including: inadequate enforcement of operating standards, failure to follow procedures, and ineffective operator training. The Entergy RCE determined that the primary cause was a failure to adhere to established Entergy standards and expectations due to a lack of consistent supervisory and management enforcement. The inspection team concluded that the finding had a cross-cutting aspect in the Human Performance cross-cutting area, Work Practices component, because Entergy did not adequately enforce human error prevention techniques, such as procedural adherence, holding pre-job briefs, self and peer checking, and proper documentation of activities during a reactor startup, which is a risk significant evolution. Additionally, licensed personnel did not effectively implement the human performance prevention techniques mentioned above, and they proceeded when they encountered uncertainty and unexpected circumstances during the reactor startup
05000352/FIN-2011004-042011Q3LimerickLicensee-Identified Violation10 CFR 50.54(q) requires, in part, that a power reactor licensee follow an emergency plan that meets the requirements of 10 CFR 50.47(b) and Appendix E to 10 CFR Part 50. Contrary to the above, Exelon did not make timely notification when the emergency action level threshold was met for HU5, Natural and Destructive Phenomena Affecting the Protected Area. Specifically, Exelon operators did not declare an Unusual Event within the required fifteen minutes of the earthquake felt onsite on August 23. The actual declaration was nine minutes late. At 1:51 PM, control room operators received a Seismic Monitor System Recording Activated alarm coincident with reports of seismic activity felt by station personnel. The seismic monitoring system at Limerick had previously been declared inoperable due to problems with its power supply, so operators began the compensatory measures which directed the operators to contact the United States Geological Survey to confirm the epicenter and magnitude of the seismic event prior to event classification. The United States Geological Survey has a call queue system to answer inquiries in an orderly manner, and Exelon was on hold until 2:11 PM. Exelon declared the Unusual Event at 2:15 PM and made all appropriate state and local notifications. Exelon entered the untimely event declaration into their corrective action program as IR 1254845. The inspectors determined that the finding was of very low safety significance (Green) in accordance with NRC IMC 0609, Appendix B, Emergency Preparedness Significance Determination Process, Sheet 2, because this was related to an actual event implementation problem for a Notice of Unusual Event.
05000352/FIN-2011004-032011Q3LimerickTest Equipment Interference Resulting in Reactor ScramA Green, self-revealing NCV of 10 CFR Part 50, Appendix B, Criterion XI, Test Control, occurred when Exelon did not adequately assess the potential impacts of test equipment on turbine trip circuitry. This resulted in an automatic reactor scram of Unit 1 when the main turbine high reactor water level trip relay inadvertently energized during a surveillance test on June 3, 2011. This test is a quarterly surveillance, designed to verify proper operation of the Digital Feed Water Level Control System (DFWLCS) which initiates a turbine trip on high reactor level. The DFWLCS has a 1 out of 2 twice logic to energize the trip relay, so each channel is tested separately to eliminate the possibility of inadvertent actuation. As an additional precaution, the surveillance procedure contains steps for the technician to verify the other channels are free of closed trip contacts prior to beginning the test. Exelon used a Simpson 260 Volt/Ohm Meter (VOM) to perform this verification by demonstrating a nominal voltage difference between each side of the contact and station ground. During this verification step, Exelon inadvertently established a direct current loop from station ground, to the floating battery ground from the 125V power supply, to the trip circuit. This completed the circuit, energized the main turbine high reactor water level trip relay, which tripped the main turbine and caused the reactor to scram. Exelon revised the test procedure to change the requirements for test instrumentation to prevent this from recurring and entered the issue into the corrective action program as IR 1224283. The inspectors determined that the performance deficiency was more than minor in accordance with IMC 0612, Appendix B, Issue Screening, because it was associated with the Equipment Performance attribute of the Initiating Events cornerstone and affected the objective to limit the likelihood of those events that upset plant stability and challenge critical safety functions during power operation. Specifically, by not considering the impact of maintenance and test equipment (M&TE) during multiple revisions of the surveillance procedure, Exelon failed to recognize a vulnerability which could lead to a plant transient. In accordance with IMC 0609, Attachment 4, Phase 1 - Initial Screen and Characterization of Findings, the finding was determined to be of very low safety significance (Green) because the finding did not contribute to both the likelihood of a reactor trip and the likelihood that mitigation equipment or functions would not be available. The inspectors determined that this performance deficiency did not reflect current performance, as the last revision to the surveillance procedure that affected M&TE requirements was greater than three years ago. As a result, the inspectors did not assign a cross-cutting aspect to this finding.
05000352/FIN-2011004-022011Q3LimerickFailure to Provide Adequate Restoration Instructions for Turbine Control Valve Online MaintenanceA Green, self-revealing finding was identified because Exelon did not provide adequate instructions for restoration of the Limerick Unit 2 number three turbine control valve (CV #3) following maintenance. During a fill and vent activity of the electro-hydraulic control (EHC) supply line for CV #3, a void in the system piping resulted in a low pressure condition at the next-in-series control valve, CV #1. The pressure drop actuated a relayed emergency trip system (RETS) pressure switch, generating a reactor protection system (RPS) 'S' side half scram signal. Combined with an 'A' side half scram signal that was previously inserted into RPS due to the CV #3 being maintained closed, an automatic reactor scram resulted. The inspectors determined that Exelon's failure to provide adequate instructions for restoration of CV #3 from maintenance was a performance deficiency. The issue was more than minor because it was associated with the Procedure Quality attribute of the Initiating Events cornerstone, and it affected the cornerstone objective of limiting the likelihood of events that upset plant stability. Specifically, on May 29, 2011, Limerick Unit 2 experienced an automatic reactor scram during restoration of turbine CV #3 from maintenance. The restoration instructions in the work order (WO) did not provide sufficient guidance to address the presence of a large air void in the EHC system that had the potential to cause EHC pressure fluctuations and resulted in a reactor scram. The finding was determined to be of very low safety significance (Green) in accordance with IMC 0609 Attachment 4, Phase 1Initial Screen and Characterization of Findings, because the finding did not contribute to both the likelihood of a reactor trip and the likelihood that mitigation equipment or functions would not be available. This finding had a cross-cutting aspect in the area of Human Performance, Decision-Making, because Exelon did not use a systematic process to make a risk-significant decision when faced with uncertain or unexpected plant conditions. Specifically, Exelon did not recognize the potential risk of the CV #3 EHC fill and vent restoration activity, and they failed to conduct a thorough technical review of the restoration plan.
05000333/FIN-2011003-012011Q2FitzPatrickUFSAR Emergency Bus Voltage Not Updated, Consistent with Current Plant ConditionsThe inspectors identified a Severity Level lV (SL lV) NCV of Title 10, Code of Federal Regulations (10 CFR) Part 50,71(e) because FitzPatrick personnel did not update the Updated Final Safety Analysis Report (UFSAR) with information consistent with plant conditions. Specifically, FitzPatrick personnel did not remove reference to or correct information in UFSAR Section 8.6.6.c, Emergency Bus Voltages When Operating From the Reserve Source, to reflect current plant conditions with regard to the listed maximum voltage capable of being produced at the emergency bus from the reserve source during a low load condition. This issue was considered within the traditional enforcement process because it had the potential to impede or impact the NRC\'s ability to perform its regulatory functions. FitzPatrick issued condition report (CR) CR-JAF-2011-03023 to address the UFSAR discrepancy. The inspectors concluded that the violation was more than minor because the longstanding and incorrect information in the UFSAR had a potential impact on safety and licensed activities. Excessive voltage on an emergency bus can result in equipment damage, or loss due to the actuation of protective devices such as overcurrent fuses. Similar to Enforcement Policy Section 6.1, example D.3, the inspectors determined the violation was of SL lV because the erroneous information not updated in the UFSAR was not used to make an unacceptable change to the facility nor did it impact a licensing or safety decision by the Nuclear Regulatory Commission (NRC).
05000333/FIN-2011003-032011Q2FitzPatrickMain Steam Isolation Valve Leak Rate Exceeds Authorized LimitThis issue was considered within the traditional enforcement process because there was no performance deficiency identified, and NRC lnspection Manual Chapter (lMC) 0612, Appendix B, lssue Screening directs disposition of such issues in accordance with the NRC Enforcement Policy. The inspectors used the Enforcement Policy, Section 6'1, Reactor Operations, to evaluate the significance of this violation. The inspectors concluded that the violation was more than minor and best characterized as Severity Level lV (very low safety significance) because it is similar to Enforcement Policy Section 6.1, Lxample 0.1. Additionally, the inspectors assessed the risk associated with the issue by using IMC 0609, Appendix A, Determining the Significance of Reactor Inspection Findings for AlPower Situations. The inspectors screened the issue in accordance with Attachment 0609.04, Phase 1 - lnitial Screening and Characterization of Findings, and determined that a Phase 2 evaluation was required, because the issue constituted an actual open pathway in the physical integrity of the reactor containment, that being the 'C' main steam line with leakage past both MSIVs in excess of the TS limit. The Phase 2 SDP process for containment barrier issues is conducted in accordance with the guidance provided in IMC 0609, Appendix H. IMC 0609, Appendix H, does not provide specific guidance on establishing the risk associated with penetration leakage for Mark I containments. Therefore, a Region I Senior Reactor Analysis (SRA) conducted a Phase 3 risk evaluation to evaluate the potential increase in the large early release frequency (LERF). The Phase 3 risk assessment uses the best available risk information to make a risk informed decision on the significance of inspection findings. The Phase 3 risk evaluation determined that the increase in LERF was likely less than the 1E-7 per year threshold and that the finding was, therefore, of very low safety significance. The SRA determined the top fifteen dominant core damage sequences from the NRC's FitzPatrick Standardized Plant Analysis Risk (SPAR) model version 8.16. The SRA used the method as outlined in Section 3.2.8, Main Steam lsolation Valve Leakage, of NUREG 1785, Basis Document for Large Early Release Frequency (LERF) Significance Determination Process (SDP). The result indicated that there was essentially no increase in LERF because the SDP already assumed that all high pressure core damage sequences would cause a large early release, so having a pair of MSIVs leaking would be no worse. ln their LER, the FitzPatrick staff documented an increase in LERF in the low E-8 per year range using their current level 2 PRA modelwhich includes MSIV leakage as a contributor to containment failure. This model goes beyond the SDP assumption that all high pressure core damage sequences result in a large early release, allowing for operator actions to reduce RPV pressure and improving the possibility of getting water to the reactor vessel or the drywell floor before reactor vessel breach. The SRA considered several qualitative factors in reaching a final risk determination for this issue. Considerations which tended to decrease the risk associated with this finding were that: 1) the leak testing methodology (low rate of pressurization) may not seat an MSIV in the same manner that would occur under actual operating conditions, given the reactor steam pressure tending to close the valves; 2) given the actual mechanisms which allowed the leakage (as described in the LER), it is likely that the two leaking MSIVs with reactor presiure tending to close the valves would have offered considerably more resistance to steam flow than if they were fully open; 3) the downstream turbine bypass and stop/throttle valves would be closed if the condenser was not available, and as such, these valves would also provide some additional (though not specifically quantifiable) isolation function; and 4) there would be significant deposition of radioactive nuclides in the main steam lines and condenser, thus limiting the radiological inventory transported to the site boundary and limiting the potentialfor a large early release. The SF(A also determined that external initiating events such as a seismic event or a fire would not significantly affect these quantitative factors, given the robustness of the main steam piping downstream of the MSIVs and the very low chance that a fire would damage this piping. Therefore, the SRA determined that both the quantitative LERF calculation and qualitative factors supported the conclusion that this finding was of very low risk significance (Green). Because this issue was of very low safety significance (Green) and it has been determined that the issue was not within Entergy personnel's ability to foresee and correct, that Entergy staff actions did not contribute to the degraded condition, and that actions taken were reasonable to identify and address this matter, and as such no performance deficiency existed, the NRC has decided to exercise enforcement discretion in accordance with Section 3.5 of the NRC Enforcement Policy and refrain from issuing enforcement action for the violation of TSs (EA-1 1-170). Further, because licensee actions did not contribute to this violation, it will not be considered in the assessment process or the NRC's Action Matrix,
05000220/FIN-2011009-012010Q4Nine Mile PointIntentional Failure to Follow ProcedureOn Friday, March 5,2010, the SE received information indicating that a charcoal sample taken from an NMP #11 R8EVS charcoal filter had failed its two-year required surveillance test (ST). The sample did not meet the minimum value for radioactive methyl iodide removal specified in NMP Technical Specifications (TS). As a result, in accordance with the TS, the NMP1 R8EVS train should have been declared inoperable and the plant should have promptly entered the seven day TS limiting condition of operation (LCO) action statement. In addition, in accordance with 10 CFR 50, App. 8. Criterion XVI and site procedures, the SE should have immediately notified his supervision of the failed ST, since it constituted a condition adverse to quality. However, the SE deliberately decided to not inform his supervision of the failed ST until Monday, March 8, 2010. The SE later admitted his failures to Constellation during the internal Constellation investigation into this matter, and the SE also cooperated with NRC investigators during the NRC 01 investigation. Because licensees are responsible for the actions of their employees and because the violation involved deliberate misconduct, the violation was evaluated under the NRC\\\'s traditional enforcement process as set forth in Section 2.2.4 of the NRC Enforcement Policy. The violation is considered to be of very low safety significance because NMP returned the #11 RBEVS train to service on March 9, 2010, which would have been within the required seven day timeframe even if the LCO had been appropriately entered on March 5, 2010, Therefore, the NRC has characterized the violation at Severity Level (SL) IV, in accordance with the NRC Enforcement Policy. The violation is being cited in the Notice in accordance with the Enforcement Policy, because the violation involved the acts of an SE who with the operability information he possessed, was in a position with responsibilities that were directly related to the oversight of licensed activities, Constellation\\\'s corrective actions included: 1) replacing the subject NMP #11 RBEVS charcoal, ensuring the #11 RBEVS train successfully passed the ST, and then returning the system to service on March 9, 2010; 2) taking appropriate disciplinary action against the involved SE and, 3) conducting training for all SEs regarding following requirements and not engaging in deliberate misconduct.
05000220/FIN-2010008-012010Q4Nine Mile PointDeliberately Failing to Use a Whole Body Contamination monitor When Exiting the Radiologically Controlled AreaThe actions of the non-licensed operator violated Nine Mile Point Unit 2 Technical Specifications Section 5.4.1, which caused Constellation to be in violation of its license conditions and NRC requirements. This section states, in part, that written procedures shall be established, implemented, and maintained covering the following activities: the applicable procedures recommended in Regulatory Guide 1.33, Revision 2, Appendix A, February 1978. Section 7.e of Appendix A of Regulatory Guide 1.33, Revision 2, lists procedures for radiation protection contamination control and radiation protection - personnel monitoring. Licensee procedure GAP-RPP-O1, Radiation Protection Program, Revision 01900, Section 3.5.2.d states, in part: To control personnel contamination, Radiation Protection should establish and maintain personnel monitoring areas at various locations throughout the RCA, and at exits from the RCA, as determined by RP Supervision. Personnel shall monitor themselves for contamination upon exiting the RCA and other RCAs as specified by RP Supervision, in a WBCM. Contrary to the above, on April 15,2010, Constellation identified that a non-licensed operator exited the RCA without first monitoring himself for contamination in a WBCM. Specifically, the non-licensed operator admitted he exited the RCA without using the WBCM in order to avoid a long line waiting to use the monitor. Later, when attempting to leave the site, the operator alarmed a portal monitor, due to contamination on his clothing. Although Constellation was initially unaware that the non-licensed operator exited the RCA without using the WBCM, Constellation is responsible for the actions of its employees. Because you are responsible for the actions of your employees, and because the violation involved deliberate misconduct, the violation was evaluated under the NRC\\\'s traditional enforcement process as set forth in Section 2.2.4 of the NRC Enforcement Policy. After considering the low level of contamination found, that no contamination left the site, and the violation was not repetitive, the NRC has categorized it at Severity Level lV in accordance with the NRC Enforcement Policy. Because this violation was of very low safety significance and was entered into Nine Mile Point\\\'s corrective action program, this violation is being treated as a non-cited violation (NCV), consistent with Section 2.3.2 of the NRC Enforcement Policy (NCV 05000410/2010008-01, Deliberately Failing to Use a Whole Body Contamination Monitor When Exiting the Radiologically Controlled Area). The current NRC Enforcement Policy is included on the NRC\\\'s website at http.//www.nrc.qov; select About NRC, Regulation, Enforcement, then, Enforcement Policy
05000387/FIN-2010004-012010Q3SusquehannaProcedural Inadequacies Result in Reactor Scram and Loss of Normal Heat SinkA self-revealing preliminary White finding regarding procedure NDAP-QA-0008, Procedure Writer\\\'s Guide, Revision 8, was identified following a July 16, 2010, flooding event in the Unit 1 condenser bay which resulted in a manual reactor scram and loss of the normal heat sink. There were three instances of inadequate procedures identified. The first instance involved maintenance procedure MT-043-001 which provided inadequate instructions regarding installation of the condenser waterbox gaskets and led to the event. In addition, two other off-normal procedures were inadequate in that they complicated operator response to the event. Specifically, operators used a diagram in off-normal procedure ON-100-003, Chemistry Anomaly, to identify and isolate the leak which was incorrect, delayed leak isolation, and resulted in a manual reactor scram in anticipation of a loss of the normal heat sink. Finally, ON-142-001, Circulating Water (CW) Leak, did not contain specific instructions to isolate a condenser waterbox leak which contributed to operators using ON-100-003 which was not intended to be used to isolate the condenser box during flooding conditions. PPL corrected the diagram error, dewatered and repaired affected equipment, and entered this issue into their CAP (1282128). This finding was determined to be more than minor as it affected the Initiating Events cornerstone attribute of Procedure Quality and its objective of limiting the likelihood of those events that upset plant stability and challenge critical safety functions during power operation. The finding was evaluated using Phases 1, 2, and 3 of the Significance Determination Process. The conclusion of the Phase 3 analysis was an estimated change in core damage frequency (CDF) of 1.1 E-6/yr (White) and an estimated change in large early release frequency (LERF) of 2.6E-7/yr (White). The finding is related to the cross-cutting area of Problem Identification and Resolution, Corrective Acton Program, in that PPL did not thoroughly evaluate problems such that the resolutions address the causes and extent of condition, as necessary. Specifically, PPL did not appropriately evaluate and correct a known issue in an off-normal procedure or adequately evaluate previous CW system waterbox manway gasket leaks to ensure that future occurrences could be prevented.
05000387/FIN-2010003-052010Q2SusquehannaConfiguration Control and Operation of ICSAn unresolved item (URI) was identified concerning configuration control and operation of the ICS-controlled feedwater and reactor vessel level control system. On April 22, 2010, during the performance of ICS testing, Unit 1 experienced a level transient and reactor scram on low water level. Historic plant startup sequences maintained the third RFPT on the turning gear, a third condensate pump running, and manual controls to parallel the second RFPT. In contrast, the third RFPT was in the idle mode and two condensate pumps were running when ICS enabled the \\\"1 B\\\" RFPT to transition from idle mode directly to FC mode as designed. PPL was conducting an RCA of the scram event at the end of the inspection period. This issue will be tracked as a URI pending inspection following completion of PPL\\\'s RCA.
05000277/FIN-2010009-012010Q2Peach BottomInaccurate Personnel History Questionnairea former contract outage employee at Peach Bottom deliberately failed to disclose on a Personal History Questionnaire (PHQ), a previous, non-nuclear employment from which he had been terminated for a positive FFD test, in order to gain unescorted access (UA) to Peach Bottom. As a result of the investigation, the NRC determined that, on September 8, 2008, the contract employee did fail to disclose his prior employment with the non-nuclear company on the PHQ, and also failed to provide information about the positive FFD test. However, after considering the information developed during the investigation, the NRC concluded that it did not have sufficient evidence to conclude that the individuals failures were deliberate. Nonetheless, as a result of these failures by the contract employee, Exelon granted the individual UA to Peach Bottom from September 11, 2008, until September 28, 2008. Exelon learned of the individuals positive FFD in August 2009, when the contract employee attempted to gain UA to Progress Energys Crystal River Nuclear Generating Plant 3 (Crystal River) Although the contract employee did not enter any Vital Areas at Peach Bottom and also did not perform work on any safety-related equipment during the time he was granted access, the contract employees actions caused Exelon to be in violation of NRC requirements, specifically: 1) 10 CFR 50.9, which states in part that information required by the Commissions regulations, orders, or license conditions to be maintained by the licensee shall be complete and accurate in all material respects; and, 2) 10 CFR 73.56(c) and Section 9.1 of the Peach Bottom Physical Security Plan, both of which state, in part, that the licensees access authorization program must provide high assurance that the individuals who are granted unescorted access are trustworthy and reliable. Although Exelon was unaware of the contract employees omission of information regarding the positive FFD test, Exelon is responsible for the adequacy of its Physical Security Plan and background checks to identify past actions and appropriately evaluate the trustworthiness and reliability of applicants for UA. (This item was also discussed in Inspection Report 2010-004.)
05000443/FIN-2009007-012009Q3SeabrookInadequate B EDG Design ChangeA self-revealing apparent violation of 10 CFR 50, Appendix B, Criterion III, Design Control was identified following a review of the identified causes for the failure of the B EDG jacket water cooling system on February 25, 2009. Specifically, NextEras failure to adequately control design changes implemented on the B EDG jacket water cooling system in January 2009 led to the failure of the gasket on flange JTR005 in the B EDG jacket water cooling system on February 25. The inspectors determined that this finding is more than minor because it is associated with the design control attribute of the Mitigating Systems Cornerstone and affects the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, design modification 08MSE11, intended to address flange JTR005 alignment and change the flange gasket design was inadequate and resulted in inoperability of the B EDG. In accordance with IMC 0609, Significance Determination Process, a Phase 3 risk analysis was performed and determined that the calculated delta CDF for the finding was 2.27E-6, which represents a low to moderate safety significance or White finding. The cause of the finding is related to the corrective action component of the cross-cutting area of problem identification and resolution because NextEra did not thoroughly evaluate problems in a timely manner such that resolutions address causes (P.1(c)). Specifically, NextEra did not adequately evaluate deficient conditions when addressing B EDG cooling water flange leaks, failed to adequately use readily available internal operating experience, and failed to adequately evaluate and correct the impact of engine vibrations on flange JTR005 integrity, contributing to a subsequent failure of the flange. (1R18
05000352/FIN-2009007-012009Q2LimerickLead maintenance technician deliberately permitted unqualified contractors to open breakers and hang clearance tagsLimerick Generating Station Technical Specifications 6.8, Procedures and Programs, requires, in part, that written procedures shall be established, implemented, and maintained covering the applicable procedures recommended in Appendix A of Regulatory Guide 1.33, Revision 2, February 1978. Regulatory Guide 1.33, Revision 2, Appendix A, February 1978, recommends administrative activities, including equipment control (i.e. locking and tagging), be covered by written procedures. Exelon Procedure OP-MA-109-101, Clearance and Tagging, Revision 6, Section 13, Worker Tagout Process, Step 13.1.3 states, Personnel using worker tagout tags shall be qualified in the clearance and tagging process. Contrary to the above, between January and July 2007 and in February 2008, the licensee failed to implement a procedure required by Technical Specification 6.8 when worker tagout tags were used by personnel at Limerick Generating Station who were not qualified in the clearance and tagging process. Specifically, a lead maintenance technician with oversight responsibilities for a contractor group deliberately permitted unqualified contractors to open breakers and hang worker tagout tags
05000352/FIN-2009007-022009Q2LimerickLead maintenance technician deliberately falsified clearance and tagging recordsTitle 10 of the Code of Federal Regulations, Part 50.9, Completeness and Accuracy of Information, requires, in part, that information required by statute or by the Commissions regulations, orders, or license conditions to be maintained by the licensee shall be complete and accurate in all material respects. Exelon Procedure OP-MA-109-101, Step 13.2.5.2 states, The Lead Worker or First Line Supervisor shall perform the Worker Tagout per the Worker Tagout Clearance Form. Step 13.2.7.5 states that when the work is complete, the Lead Worker or First Line Supervisor shall complete the Worker Tagout Clearance Form and return it to the workgroup Supervisor to be retained/recorded in the work package. Contrary to the above, between January and July 2007 and in February 2008, a lead maintenance technician, when documenting worker tagouts on Worker Tagout Clearance Forms, created information maintained by the licensee that was not complete and accurate in all material respects. Specifically, the lead maintenance technician falsified Worker Tagout Clearance Forms by forging the initials of qualified maintenance technicians, indicating that they had conducted the clearance and tagging activities when, in fact, the activities had been performed by unqualified contractors.
05000317/FIN-2008502-012009Q1Calvert CliffsFailure to maintain emergency plans (Section 1EP4)Constellation identified an apparent violation associated with the failure to meet emergency preparedness planning standard 10 CFR 50.47(b)(4). For the period of August 31, 2005, until April 10, 2008, the emergency action level (EAL) tables fission product barrier matrix contained an inaccurate threshold associated with identifying the potential loss of the containment barrier. The error was not identified by Constellation prior to implementation of the revised EAL table. Constellation evaluated this condition and took prompt actions to correct the inaccurate EAL. The finding was more than minor because it was associated with the procedure quality (EAL changes) attribute of the Emergency Preparedness cornerstone and affected the associated cornerstone objective to ensure that the licensee is capable of implementing adequate measures to protect the health and safety of the public in the event of a radiological emergency. This finding is associated with risk significant planning standard 10 CFR 50.47(b)(4) and 10 CFR 50 Appendix E, IV.B, Assessment Actions. The NRC determined that the finding is preliminarily White, a finding with low to moderate safety significance, that may require additional NRC inspection. Using Emergency Preparedness Significance Determination Process, Inspection Manual Chapter (IMC) 0609, Appendix B, Sheet 1, Failure to Comply, the finding was determined to be a risk significant planning standard (RSPS) problem and an RSPS degraded function (White). Additionally, IMC 0609, Appendix B contains an example of Loss of RSPS Function for 10 CFR 50.47 (b)(4); more than one Alert, or any Site Area Emergency would not be declared that should be declared, resulting in a White finding. There is no crosscutting aspect associated with this finding since it is not reflective of current licensee performance. (Section 1EP4)
05000387/FIN-2008302-012008Q3SusquehannaFailure to Provide Complete and Accurate NRC License ApplicationThe NRC identified a Level IV non-cited violation of 10 CFR 50.9, Completeness and Accuracy of Information because PPL submitted a license application for a reactor operator to take an initial NRC license examination that incorrectly stated that the applicant was medically qualified with restrictions. The performance was reviewed for any cross cutting aspects and none were identified. This finding was more than minor because it impacted the NRCs ability to perform its regulatory function and was therefore evaluated using the traditional enforcement process. Specifically, PPL submitted a license application for a reactor operator to take an NRC license examination that incorrectly stated that the applicant was medically qualified with restrictions. This information could have resulted in an operator being licensed that was not medically qualified. The finding is of very low significance because it did not result in the NRC making an incorrect licensing decision and PPL took adequate corrective actions and on July 14, 2008 requested withdrawal of this reactor operator license application. (Section 4OA5
05000277/FIN-2008405-012008Q1Peach BottomExtent of Condition and Corrective Action Program Usage for Operator Watch Standing Issues. (Section 4OA2.2)On September 10, 2007, representatives of WCBS-TV (New York City) contacted the NRC stating that they possessed videotapes of inattentive security officers at the Peach Bottom Atomic Power Station (PBAPS). Based upon this information, the NRC Region I Regional Administrator directed implementation of enhanced inspection oversight of security activities by the resident inspectors at PBAPS, and verbally informed Exelon management of the information received. Exelon commenced an internal investigation based upon this information. On September 19, 2007, WCBS-TV shared the videotapes with the NRC staff, which viewed the videos and determined that the situation warranted an Augmented Inspection. An Augmented Inspection Team (AIT) completed an inspection at PBAPS from September 21 through 28, 2007. The team concluded that Exelons prompt compensatory measures and corrective actions in response to the videotaped inattentive security officers at PBAPS were appropriate and ensured the stations ability to satisfy the Security Plan. However, the team determined that the security officer inattentiveness affected the defense-in-depth strategy, and that security force supervisors were not effective in ensuring unacceptable behavior was promptly identified and corrected. The AIT inspection results were published on November 5, 2007 in NRC Inspection Report 2007404 (ADAMS accession number ML073090061). On October 4, 2007, Exelon sent a letter to the NRC Region I Regional Administrator (ML072850708) which described their completed actions and initiatives to address the issues identified by the AIT. These initiatives included terminating the current security contract with their contractor and transitioning to a proprietary security force. Exelon also described plans to complete a root cause analysis of the security officer inattentiveness, identify corrective actions, and perform safety conscious work environment (SCWE) surveys of the Peach Bottom Security organization. On October 19, 2007, the NRC issued a Confirmatory Action Letter (CAL) to confirm Exelons commitments to assure that security officers remain attentive at all times while on duty (ML072920283). Exelon completed their root cause analysis in October 2007 and identified several causal factors related to the security officer inattentiveness issues and specific corrective actions to address the causal factors. One of the corrective actions was to perform a systematic SCWE assessment of all work groups at PBAPS (including the Security work group) based on an integrated review of information from the PBAPS Corrective Action Program (CAP), Employee Concerns Program (ECP), publicly available NRC allegation statistics, and SCWE surveys. The NRC conducted an AIT follow-up inspection from November 5 through 9, 2007, to review Exelons root cause analysis report and their planned corrective actions. The inspectors concluded the corrective actions were appropriate. With regard to the security officer inattentiveness issue, the AIT follow-up inspection identified a finding regarding Exelons failure to maintain the minimum required number of available security officer responders and an associated failure to implement an effective behavior observation program. The AIT follow-up inspection determined that the finding was related to SCWE because it involved security supervisors who did not encourage the free flow of information related to raising safety concerns, and who did not respond to security officer safety concerns in an open, honest, and non-defensive manner. The NRC determined the finding was of low to moderate safety significance (White). This was documented in a subsequent letter to Exelon dated February 12, 2008 (ML080440012). The AIT follow-up inspection results were issued in NRC Inspection Report 2007405 (ML073550590) dated December 21, 2007. Region I determined that Exelons actions to address the PBAPS inattentive security officer issues and their plans to transition to a proprietary security force warranted additional inspection and oversight beyond that specified in the Reactor Oversight Process (ROP) baseline inspection program. On November 28, 2007, the Regional Administrator recommended, through a Deviation Memorandum to the NRCs Executive Director for Operations (EDO), that PBAPS warranted additional inspection resources (ML073320344). One additional inspection activity was to conduct inspections of Exelons efforts to address SCWE issues, including a review of the results of SCWE surveys conducted at the site. The EDO approved this request on November 28, 2007. Consistent with the planned corrective actions from their root cause evaluation, Exelon arranged for a third party to conduct a survey of the SCWE at PBAPS. The survey was in the form of a series of questions provided to the staff in January 2008. The survey was completed and the results provided to Exelon in February 2008. A separate SCWE survey of the security organization was also conducted during November 2007. Exelon utilized the survey results to complete a self-assessment of the SCWE at PBAPS. In accordance with the NRC Action Matrix Deviation Memorandum, this inspection was conducted onsite from March 24 though 28, 2008, to review Exelons self-assessment of the PBAPS SCWE, including a review of the results of their SCWE survey. Other completed Deviation Memorandum activities included a security organization performance monitoring inspection (ML080720038) and a root cause corrective action evaluation (ML081090161).
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